In many areas of the world, subterranean formations which contain large deposits of viscous petroleum are unconsolidated or partially consolidated in that the sand particles in the formation are wearkly bonded together. Such formations may be found in the Athabasca and Cold Lake regions in Alberta, And the Sisquoc region in California, U.S.A. These deposits are often referred to as "tar sand", "oil sand" or "heavy oil" due to the high viscosity of the hydrocarbons they contain. While some distinctions have arisen between tar sands and oil sands (viscosity between about 10,000 and 100,000 cP at reservoir temperature) and heavy oil (viscosity between about 1,000 and 10,000 cP at reservoir temperature), these terms will be used interchangeably herein. Tar sands often contain a viscous hydrocarbon material, commonly referred to as bitumen, in an amount which ranges from 5 to about 20% by weight. Bitumen is normally immobile at typical reservoir temperatures. However, at higher temperatures, such as temperatures of 90.degree. C. or greater, the bitumen generally becomes mobile with a viscosity of less than 345 centipoise.
Since most tar sand deposits are too deep to be mined economically, various in-situ recovery processes have been proposed for separating the bitumen from the sand in the formation itself and producing the bitumen through a well drilled into the deposit. Among the various methods for in-situ recovery of bitumen from tar sands, processes which involve the injection of steam are generally regarded as most economical and efficient. Steam can be utilized to heat and fluidize the immobile bitumen and, in some cases to drive the mobilized bitumen towards production means.
The most common and proven method for recovering viscous hydrocarbon is by using steam stimulation techniques which involve heating a formation in the vicinity of a well to stimulate production back through the same well. In this type of process, steam is injected into a formation by means of a well and the well is shut-in to permit the steam to heat the bitumen, thereby reducing its viscosity. Subsequently, all formation fluids, including mobilized bitumen, water and steam, are produced from the same well using accumulated reservoir pressure as the driving force for production.
During production of formation fluids from such tar and oil-sands, the sand particles are removed from the formation and carried by the fluids to the borehole of the well. This produced sand at the borehole causes many problems. Produced sand may plug and erode the well, production tubing, pumps and other equipment and prevent petroleum production from the well. The sand also accumulates in stock tanks and catalyst beds causing expensive downtime for sand removal. If the sand is produced in fluids flowing at a high velocity, serious erosion, similar to erosion caused by sandblasting, may occur in tubular goods and other production equipment. Such high velocity fluid flows occur during steam and water enhanced oil recovery and in production from high pressure formations.
Various methods currently exist for controlling sand production from a subterranean formation. However, each method has its own disadvantages.
The method generally used for sand control employs the installation of slotted liners or screens in the tubular goods. Such liners or screens are designed to prevent the flow of sand into the well tubing by filtering such sand out of the produced formation fluids. The openings in the liners or screens are designed to prevent the flow of sand through them. However, such liners and screens often fail due to erosion and corrosion. They also may become plugged and prevent the flow of fluids from the formation. Erosion, corrosion and plugging make workover necessary to repair well equipment and allow further production.
Another sand control method requires placing a clean fine gravel pack around the wellbore. This makes a filter bed with small openings which prevents movement of produced sand into the wellbore. The filter bed also provides support for the unconsolidated formation. However, the particles in the gravel pack filter bed are not bound together and may move to plug well flow passages.
Several sand control methods involving consolidation of the sand formation surrounding the borehole have been suggested. Methods exist for consolidating sand formations by introducing cements, polymers, resins or ceramics outside the wellbore into the surrounding formation. U.S. Pat. No. 4,232,740 (Park) discloses a formation consolidation method which cements the formation sand particles together by injecting a series of aqueous solutions containing calcium hydroxide and a calcium salt with a solubility greater than that of calcium hydroxide. In the method of U.S. Pat. No. 4,391,555 (Burger et al) a formation is consolidated by injecting into the formation a liquid containing both a catalyst and a polymerizable chemical compound which hardens upon contact with an oxidizing gas. After injection of the liquid, an oxidizing gas is introduced into the formation, causing the polymer to solidify and consolidate the formation. The method of U.S. Pat. No. 3,332,490 (Burtch et al) places a devitrifiable glass in an unconsolidated formation, heats the formation to melt the glass, then applies further heat to devitrify the glass and consolidate the formation.
The sand control methods described above tend to stabilize the sand formations; however, they require placing potentially expensive materials outside the wellbore under tightly controlled conditions. Also, these forms of consolidation may reduce permeability, fail during high temperature recovery processes and require injection into a clean gravel pack to be effective.
More recently, methods for consolidating a formation for sand control using coking-type reactions have been employed. Terwillager, Smith and Goodwin in "Warm-Air-Coking--A New Completion Method for Unconsolidated Sands", Journal of Petroleum Engineering, April, 1964, pp. 367-371 discloses a "warm-air coking" method for consolidating sand formations which contain heavy crude. In this method, warm air is injected into an unconsolidated formation to oxidize the heavy crude. Oxidation is continued until an insoluble coke or resin forms to cement the sand particles and consolidate the formation. In U.S. Pat. No. 3,974,877 (Redford) sand control is provided by establishing a clean gravel pack around the wellbore, introducing bitumens into the gravel pack and injecting a mixture of steam and oxygen to form a permeable solid. However, processes which inject oxygen or air must be performed in ways which avoid spontaneous ignition in the formation. These limitations tend to render such methods expensive and unreliable. U.S. Pat. No. 3,333,636 (Groves et al) claims another coking method for formation consolidation. In Groves et al coke is formed in the sand surrounding the wellbore by injecting a sulfonating agent. The specific sulfonating agent used is sulfur trioxide. However, sulfur trioxide is difficult and expensive to handle. U.S. Pat. No. 3,437,144 (Fisher) claims a method for consolidating a formation by dissolving sulfur in oil and injecting the solution into the formation. The injected solution is then subjected to an elevated temperature, charring the oil to form a binder. However, this method requires the added expense of introducing oil into the wellbore. Also, the amount of sulfur which can be introduced into the wellbore is limited by the amount of sulfur which can be dissolved in the oil.